Item 2. Management’s Discussion and Analysis
of Financial Condition and Results of Operations
The following discussion is intended to assist
you in understanding our business and results of operations together with our
present financial condition. This section should be read in conjunction with
our historical consolidated financial statements and notes.
Certain statements in our discussion below are
forward-looking statements. These forward-looking statements involve risks and
uncertainties. We caution that a number of factors could cause actual results
to differ materially from those implied or expressed by the forward-looking
statements. Please see “Cautionary Statement Regarding Forward-Looking
Statements.”
Overview
We are an
independent oil and natural gas company engaged in the acquisition, development,
exploration and production of oil and natural gas properties. Our core
operations are primarily focused in the Permian Basin of Southeast
New Mexico and West Texas. Concho’s legacy in the Permian Basin provides
us a deep understanding of operating and geological trends. We are also at the
forefront of applying new technologies, such as horizontal drilling and
enhanced completion techniques, throughout our three core operating areas: the
New Mexico Shelf, the Delaware Basin and the Midland Basin. In the New Mexico
Shelf, we primarily target the Yeso formation with horizontal drilling; in the
Delaware Basin, we use horizontal drilling to target the Bone Spring formation
(including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale
formation; and in the Midland Basin, we target the Wolfcamp and Spraberry
formations with horizontal drilling.
Oil comprised 59 percent of our 623.5 MMBoe of estimated proved
reserves at December 31, 2015 and 62.7 percent of our 25.9 MMBoe of
production for the six months ended
June 30,
2016
.
We seek to operate the wells in which we own an
interest, and we operated wells that accounted for 93 percent of our proved developed
producing PV-10 and 78.9 percent of our 7,636 gross wells at
December 31, 2015
. By controlling operations, we are able to more effectively
manage the cost and timing of exploration and development of our properties,
including the drilling and stimulation methods used.
Financial
and Operating Performance
Our financial
and operating performance for the six months ended June 30, 2016 and 2015
included the following highlights:
·
Net loss was $
1.3 b
illion ($(9.94)
per diluted share) as compared to net loss of $113.0
million ($(0.97)
per
diluted share) for the first six months of 2016 and 2015, respectively. The increase
in net loss was primarily due to:
•
$1.5
billion in impairments of long-lived assets during the six months ended June
30, 2016, primarily attributable to properties in our New Mexico Shelf area;
•
$271.1
million decrease in oil and natural gas revenues as a result of a
30 percent decrease in commodity price realizations per Boe
(excluding the effects of derivative activities), partially
offset by
a 2
percent increase in
production
;
•
$
184.8 million increase in the loss on derivatives during
the six months ended June 30, 2016, as compared to 2015;
•
$26.4
million increase in exploration and abandonment expense
primarily due to leasehold abandonments during the
six
months ended
June 30,
2016
as compared to 2015; and
•
$19.0
million increase in depreciation, depletion and amortization expense, primarily
due to an increase in production;
partially offset
by:
•
$685.5
million change in our income tax benefit due to the increase in our net loss
before income taxes;
•
$111.5
million increase in (gain) loss on disposition of assets, net primarily due to
our February 2016 asset divestiture; and
•
$42.6
million decrease in oil and natural gas production expense.
·
Average daily sales volumes of
142,319
Boe
per day during the first six months of 2016 were up slightly as compared to
139,826 Boe per day during the first six months of 2015.
·
Net cash provided by operating activities decreased by
approximately $239.1 million to $249.8
million
for
the first six months of 2016, as compared to $488.9
m
illion
in the first six months of 2015, primarily due to a decrease in oil and natural
gas revenues, partially offset by a decrease in production and cash general and
administrative expenses.
·
Cash increased by approximately $252.7 million during the first
six months of 2016 primarily as a result of operating cash flows and our
divestiture that closed in February 2016, partially offset by the cash
consideration related to our asset acquisition that closed in March 2016.
Commodity Prices
Our
results of operations are heavily influenced by commodity prices. Commodity
prices may fluctuate widely in response to (i) relatively minor changes in the
supply of and demand for oil, natural gas and natural gas liquids, (ii) market
uncertainty and (iii) a variety of additional factors that are beyond our
control. Factors that may impact future commodity prices, including the price
of oil, natural gas and natural gas liquids, include, but are not limited to:
·
continuing economic uncertainty
worldwide;
·
political and economic developments in
oil and natural gas producing regions, including Africa, South America and the
Middle East;
·
the extent to which members of the
Organization of Petroleum Exporting Countries and other oil exporting nations
are able to continue to manage oil prices and production controls;
·
technological advances affecting energy
consumption and energy supply;
·
domestic and foreign governmental
regulations, including limits on the United States’ ability to export crude
oil, and taxation;
·
the level of global inventories;
·
the proximity, capacity, cost and
availability of pipelines and other transportation facilities, as well as the
availability of commodity processing and gathering and refining capacity;
·
risks related to the concentration of
our operations in the Permian Basin of Southeast New Mexico and West Texas and
the level of commodity inventory in the Permian Basin;
·
the quality of the oil we produce;
·
the overall global demand for oil
natural gas and natural gas liquids;
·
the domestic and foreign supply of oil,
natural gas and natural gas liquids;
·
political and economic events that
directly or indirectly impact the relative strength or weakness of the United
States dollar, on which oil and natural gas commodity prices are benchmarked
globally, against foreign currencies;
·
the effect of energy conservation
efforts;
·
the price and availability of
alternative fuels; and
·
overall North American oil, natural gas
and natural gas liquids supply and demand fundamentals, including:
•
the United States economy,
•
weather conditions, and
•
liquefied natural gas deliveries to and exports from the
United States.
Although
we cannot predict the occurrence of events that may affect future commodity
prices or the degree to which these prices will be affected, the prices for any
commodity that we produce will generally approximate current market prices in
the geographic region of the production. From time to time, we expect that we
may economically hedge a portion of our commodity price risk to mitigate the
impact of price volatility on our business. See Notes 8 and 15 of the Condensed
Notes to Consolidated Financial Statements included in “Item 1.
Consolidated Financial Statements (Unaudited)” for additional information
regarding our commodity derivative positions at June 30, 2016 and additional
derivative contracts entered into subsequent to June 30, 2016, respectively.
Oil and natural gas prices have been subject to
significant fluctuations during the past several years. In general, average oil
and natural gas prices were significantly lower during the comparable periods of
2016 measured against 2015. The following table sets forth the average New York
Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three and six
months ended
June 30, 2016
and 2015, as well as the high and low NYMEX
prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
45.56
|
|
$
|
57.80
|
|
$
|
39.65
|
|
$
|
53.33
|
|
Natural gas (MMBtu)
|
|
$
|
2.24
|
|
$
|
2.74
|
|
$
|
2.12
|
|
$
|
2.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High and Low NYMEX prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
51.23
|
|
$
|
61.43
|
|
$
|
51.23
|
|
$
|
61.43
|
|
|
Low
|
|
$
|
35.70
|
|
$
|
49.14
|
|
$
|
26.21
|
|
$
|
43.46
|
|
Natural gas (MMBtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
2.92
|
|
$
|
3.02
|
|
$
|
2.92
|
|
$
|
3.23
|
|
|
Low
|
|
$
|
1.90
|
|
$
|
2.49
|
|
$
|
1.64
|
|
$
|
2.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural
gas price reached highs and lows of $48.99 and $40.06 per Bbl and $3.02 and
$2.66 per MMBtu, respectively, during the period from
July 1, 2016
to August 1, 2016. At August 1, 2016, the NYMEX oil price and NYMEX natural gas
price were $40.06 per Bbl and $2.77 per MMBtu, respectively.
Recent Events
Asset acquisition.
In
March 2016, we completed an acquisition of 80 percent of a third-party seller’s
interest in certain oil and natural gas properties and related assets in the
southern Delaware Basin. As consideration for the acquisition, we issued to the
seller approximately 2.2 million shares of common stock with an approximate
value of $230.8 million, $146.2 million in cash and $40.0 million to carry a
portion of the seller’s future development costs in these properties.
Asset divestiture.
In February 2016, we sold certain assets in the northern Delaware Basin for
proceeds of approximately $292.0 million and recognized a pre-tax gain of approximately
$110.1 million.
Derivative Financial Instruments
Derivative financial instrument exposure.
At
June 30, 2016
, the fair value of our financial derivatives was a net
asset
of $
176.0
million. All of our counterparties to these financial derivatives
are parties or affiliates of parties to our credit facility and have their
outstanding debt commitments and derivative exposures collateralized pursuant
to our credit facility. Under the terms of our financial derivative instruments
and their collateralization under our credit facility, we do not have exposure
to potential “margin calls” on our financial derivative instruments. We
currently have no reason to believe that our counterparties to these commodity
derivative contracts are not financially viable. Our credit facility does not
allow us to offset amounts we may owe a lender against amounts we may be owed
related to our financial instruments with such party or its affiliates.
New commodity derivative contracts.
After June 30, 2016, we entered into the following
oil price swaps, oil basis swaps and natural gas price swaps to hedge
additional amounts of our estimated future production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
390,000
|
|
390,000
|
|
390,000
|
|
390,000
|
|
1,560,000
|
|
|
Price per Bbl
|
$
|
49.24
|
$
|
49.24
|
$
|
49.24
|
$
|
49.24
|
$
|
49.24
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
360,000
|
|
364,000
|
|
368,000
|
|
368,000
|
|
1,460,000
|
|
|
Price per Bbl
|
$
|
(0.50)
|
$
|
(0.50)
|
$
|
(0.50)
|
$
|
(0.50)
|
$
|
(0.50)
|
Natural Gas Swaps: (c)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
1,985,315
|
|
1,066,642
|
|
1,110,441
|
|
920,000
|
|
5,082,398
|
|
|
Price per MMBtu
|
$
|
3.21
|
$
|
3.16
|
$
|
3.16
|
$
|
3.14
|
$
|
3.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The index prices for the oil
price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly
average futures price.
|
|
(b)
|
The basis differential price is
between Midland – WTI and Cushing – WTI.
|
(c)
|
The index prices for the natural
gas price swaps are based on the NYMEX – Henry Hub last trading day futures
price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of Operations
The following table sets forth summary
information concerning our production and operating data for the three and six
months ended
June 30, 2016
and 2015. Because of normal production
declines, increased or decreased drilling activities, fluctuations in commodity
prices and the effects of acquisitions or divestitures, the historical
information presented below should not be interpreted as being indicative of
future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
8,137
|
|
|
9,031
|
|
|
16,237
|
|
|
17,097
|
|
|
Natural gas (MMcf)
|
|
|
30,434
|
|
|
26,283
|
|
|
57,991
|
|
|
49,268
|
|
|
Total (MBoe)
|
|
|
13,209
|
|
|
13,412
|
|
|
25,902
|
|
|
25,308
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
89,418
|
|
|
99,242
|
|
|
89,214
|
|
|
94,459
|
|
|
Natural gas (Mcf)
|
|
|
334,440
|
|
|
288,824
|
|
|
318,632
|
|
|
272,199
|
|
|
Total (Boe)
|
|
|
145,158
|
|
|
147,379
|
|
|
142,319
|
|
|
139,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
41.68
|
|
$
|
52.14
|
|
$
|
35.80
|
|
$
|
47.99
|
|
|
Oil, with derivatives (Bbl) (a)
|
|
$
|
61.46
|
|
$
|
63.56
|
|
$
|
61.18
|
|
$
|
63.39
|
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
1.88
|
|
$
|
2.53
|
|
$
|
1.70
|
|
$
|
2.65
|
|
|
Natural gas, with derivatives (Mcf) (a)
|
|
$
|
2.13
|
|
$
|
2.88
|
|
$
|
1.95
|
|
$
|
2.97
|
|
|
Total, without derivatives (Boe)
|
|
$
|
30.00
|
|
$
|
40.07
|
|
$
|
26.25
|
|
$
|
37.57
|
|
|
Total, with derivatives (Boe) (a)
|
|
$
|
42.78
|
|
$
|
48.44
|
|
$
|
42.72
|
|
$
|
48.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
5.83
|
|
$
|
7.30
|
|
$
|
6.54
|
|
$
|
7.46
|
|
|
Oil and natural gas taxes
|
|
$
|
2.51
|
|
$
|
3.30
|
|
$
|
2.15
|
|
$
|
3.12
|
|
|
Depreciation, depletion and amortization
|
|
$
|
21.27
|
|
$
|
22.72
|
|
$
|
22.82
|
|
$
|
22.60
|
|
|
General and administrative
|
|
$
|
4.04
|
|
$
|
4.54
|
|
$
|
4.14
|
|
$
|
4.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the
effect of net cash receipts from derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
(in thousands)
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
160,968
|
|
$
|
103,129
|
|
$
|
412,095
|
|
$
|
263,315
|
|
|
|
Natural gas derivatives
|
|
|
7,781
|
|
|
9,123
|
|
|
14,584
|
|
|
16,093
|
|
|
|
|
Total
|
|
$
|
168,749
|
|
$
|
112,252
|
|
$
|
426,679
|
|
$
|
279,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The presentation
of average prices with derivatives is a result of including the net cash
receipts from commodity derivatives that are presented in our statements of
cash flows. This presentation of average prices with derivatives is a means
by which to reflect the actual cash performance of our commodity derivatives
for the respective periods and presents oil and natural gas prices with
derivatives in a manner consistent with the presentation generally used by
the investment community.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$396.3 million for the three months ended
June 30, 2016
, a
decrease of
$141.1 million (26
percent
) from $537.4 million for
2015
.
This decrease was primarily due to the decrease in realized oil and natural gas
prices. Specific factors affecting oil and natural gas revenues include the
following:
·
total oil production was 8,137
MBbl
for the
three months ended
June 30, 2016
, a
decrease
of 894
MBbl
from 9,031
MBbl
for
2015
;
·
average realized oil price (excluding the effects of derivative
activities) was
$41.68
per Bbl during the three months ended
June 30, 2016
, a
decrease of 20
percent
from
$52.14
per Bbl
during
2015
.
For the three
months ended June 30, 2016, our crude oil price differential relative to NYMEX
was $(3.88) per Bbl, or a realization of approximately 91.5 percent, as
compared to a crude oil price differential relative to NYMEX of $(5.66) per
Bbl, or a realization of approximately 90.2 percent, for 2015. We incur fixed
deductions from the posted Midland oil price based on the location of our oil
within the Permian Basin. Additionally, the basis differential between the
location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for
our oil directly impacts our realized oil price. For the three months ended
June 30, 2016 and 2015, the average market basis differential between
WTI-Midland and WTI-Cushing was a price reduction of $
0.17
per
Bbl and $
0.60
per
Bbl, respectively;
·
total natural gas production was 30,434
MMcf
for the three months ended
June 30, 2016
, an
increase
of 4,151
MMcf
(16
percent
) from 26,283
MMcf
for
2015
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$1.88
per Mcf during the
three months ended
June 30, 2016
, a decrease of 26
percent
from
$2.53
per Mcf during
2015.
For the three months ended June 30, 2016 and 2015, we realized approximately
83.9 percent and 92.3 percent, respectively, of the average NYMEX natural gas
prices for the respective periods. Factors contributing to the decrease in our
realized gas price (excluding the effects of derivatives) as a percent of NYMEX
during the three months ended June 30, 2016 as compared to 2015 include (i) a
decrease in the posted regional natural gas prices on which we are paid while
the NYMEX natural gas price decreased at a lesser rate, (ii) increased
deductions and fees from the natural gas price on which we are paid, comparatively
and (iii) the average Mont Belvieu price of $18.16 per Bbl compared to $18.67
per Bbl during the three months ended June 30, 2016 and 2015 respectively.
During December 2015, a third-party
natural gas processing plant located in the northern Delaware Basin became
inoperable following an explosion. The plant became fully operational during
April 2016.
Production expenses.
The following table provides the
components of our total oil and natural gas production costs for the three
months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
72,282
|
|
$
|
5.47
|
|
$
|
92,059
|
|
$
|
6.86
|
Workover costs
|
|
|
4,793
|
|
|
0.36
|
|
|
5,886
|
|
|
0.44
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
3,358
|
|
|
0.25
|
|
|
6,308
|
|
|
0.47
|
|
Production
|
|
|
29,791
|
|
|
2.26
|
|
|
38,012
|
|
|
2.83
|
|
|
Total oil and natural gas production expenses
|
|
$
|
110,224
|
|
$
|
8.34
|
|
$
|
142,265
|
|
$
|
10.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have
some control over lease operating expenses and workover costs on properties we
operate, but production and ad valorem taxes are related to commodity prices.
Lease operating expenses were $72.3 million ($5.47
per Boe) for the three months ended
June 30,
2016
, which was a decrease of
$19.8 million from $92.1 million ($6.86 per Boe) for the three months ended
June 30, 2015
.
The decrease in lease operating expenses during the second quarter of 2016 as
compared to 2015 was due primarily to (i)
a
focused effort to identify operational cost efficiencies,
(ii) reduced water disposal costs and (iii) an
overall decrease in the costs for goods and services
.
The decrease
in lease operating expenses per Boe was primarily due to
the reduction in lease operating expenses noted
above while production remained relatively flat period over period
.
Workover expenses were approximately $4.8 million
and $5.9 million for the three months ended
June
30, 2016
and 2015, respectively.
The decrease was primarily related to less overall activity during the second
quarter of 2016 as compared to 2015.
Production taxes per unit of production were $2.26
per Boe during the three months ended
June 30,
2016
, a decrease of 20 percent
from $2.83 per Boe during
2015
. Over the same period, our revenue per Boe
prices (excluding the effects of derivatives) decreased 25 percent. The
decrease in production taxes per unit of production was directly related to the
decrease in oil and natural gas prices. Included in the second quarter of 2015
were tax credits of approximately $1.3 million that related to certain wells in
Texas qualifying for reduced severance taxes. Notwithstanding the impact of
these tax credits, production taxes per unit of production would have decreased
24 percent period over period.
Exploration
and abandonments expense.
The following table provides a breakdown of our exploration and abandonments
expense for the three months ended
June 30,
2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
3,154
|
|
$
|
2,054
|
Exploratory dry hole costs
|
|
|
6,701
|
|
|
8,208
|
Leasehold abandonments
|
|
|
11,197
|
|
|
1,444
|
Other
|
|
|
222
|
|
|
314
|
|
Total exploration and abandonments
|
|
$
|
21,274
|
|
$
|
12,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense for the
periods presented above primarily consists of the costs of acquiring and
processing geophysical data and core analysis.
Our exploratory dry hole costs during the three
months ended
June 30, 2016
were primarily related to an uneconomic well
in our Delaware Basin area that was attempting to establish commercial
production through testing of multiple zones. Our exploratory dry hole costs
during the three months ended
June 30, 2015
were primarily related to an uneconomic well
in our Delaware Basin area that was attempting to establish production in a
zone not previously producing in the general area.
For the three months ended
June 30, 2016 and 2015
, we recorded approximately $11.2 million and
$1.4 million, respectively, of leasehold abandonments. For the three
months ended
June 30, 2016,
our abandonments were primarily within our
Delaware Basin area where we identified (i) drilling locations which, based on
multiple factors, are no longer likely to be drilled, (ii) acreage where we
have no future development plans and (iii) expiring acreage.
Depreciation, depletion and amortization
expense.
The following table provides components of our
depreciation, depletion and amortization expense for the three months ended
June 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
275,299
|
|
$
|
20.84
|
|
$
|
299,812
|
|
$
|
22.35
|
Depreciation of other property and equipment
|
|
|
5,301
|
|
|
0.40
|
|
|
4,624
|
|
|
0.34
|
Amortization of intangible assets - operating rights
|
|
|
366
|
|
|
0.03
|
|
|
366
|
|
|
0.03
|
|
Total depletion, depreciation and amortization
|
|
$
|
280,966
|
|
$
|
21.27
|
|
$
|
304,802
|
|
$
|
22.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period
end
|
|
$
|
39.63
|
|
|
|
|
$
|
68.17
|
|
|
|
Natural gas price used to estimate proved natural gas
reserves at period end
|
|
$
|
2.24
|
|
|
|
|
$
|
3.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas
properties was $275.3 million ($20.84 per Boe) for the three months ended June
30, 2016, a decrease of $24.5 million (8 percent) from $299.8 million
($22.35 per Boe) for 2015. The decrease in depletion expense was primarily due
to a lower depletion rate per Boe coupled with a slight decrease in production.
The decrease in depletion expense per Boe period over period was primarily due
to
a non-cash impairment charge of
approximately $1.5 billion recorded in the first quarter of 2016, partially
offset by an overall decrease in proved reserves period over period caused by
(i) lower commodity prices and (ii) reclassification of proved reserves to
unproven that are no longer expected to be developed within the five years of
their initial recording as required by SEC rules, which were partially offset
by capital cost reductions.
The increase in depreciation expense was
primarily associated with additional other property and equipment related to
buildings and other items.
Impairments of long-lived assets.
We periodically review our long-lived assets to
be held and used, including proved oil and natural gas properties and their
integrated assets, whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable, for instance when there are
declines in commodity prices or well performance. We review our oil and natural
gas properties by depletion base. An impairment loss is indicated if the sum of
the expected undiscounted future net cash flows is less than the carrying
amount of the assets. If the estimated undiscounted future net cash flows are
less than the carrying amount of our assets, we recognize an impairment loss
for the amount by which the carrying amount of the asset exceeds the estimated
fair value of the asset.
We calculate the expected undiscounted future
net cash flows of our long-lived assets and their integrated assets using
management’s assumptions and expectations of (i) commodity prices, which are
based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii)
production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated
proved reserves and risk-adjusted probable and possible reserves, and (vii)
prevailing market rates of income and expenses from integrated assets.
At
June 30, 2016, o
ur estimates of commodity prices for purposes
of determining undiscounted future cash flows are based on the NYMEX strip, which
ranged from a 2016 price of $49.54 per barrel of oil and $3.04 per Mcf of natural
gas to a 2023 price of $57.77 per barrel of oil and $3.50 per Mcf of natural
gas. Commodity prices for this purpose were held flat after 2023.
We calculate the estimated fair values of our
long-lived assets and their integrated assets using a discounted future cash
flow model. Fair value assumptions associated with the calculation of
discounted future net cash flows include (i) market estimates of commodity
prices, (ii) pricing adjustments for differentials, (iii) production costs,
(iv) capital expenditures, (v) production volumes, (vi) estimated proved
reserves and risk-adjusted probable and possible reserves, (vii) prevailing
market rates of income and expenses from integrated assets and (viii) discount
rate. The expected future net cash flows were discounted using an annual rate
of 10 percent to determine fair value. We did not recognize an impairment
charge during the three months ended June 30, 2016.
It is reasonably possible that the estimate of
undiscounted future net cash flows may change in the future resulting in the
need to impair carrying values. The primary factors that may affect estimates
of future net cash flows are (i) commodity futures prices, (ii) increases or
decreases in production and capital costs, (iii) future reserve volume adjustments,
both positive and negative, to proved reserves and appropriate risk-adjusted
probable and possible reserves, (iv) results of future drilling activities and
(v) changes in income and expenses from integrated assets. If the oil and
natural gas prices used in this analysis would have been approximately 10 percent
lower as of June 30, 2016 with no other changes in capital costs, operating
costs, price differentials, or reserve volumes, no impairment would be
indicated.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the three months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
46,872
|
|
$
|
3.55
|
|
$
|
51,847
|
|
$
|
3.87
|
Non-cash stock-based compensation
|
|
|
12,451
|
|
|
0.94
|
|
|
15,450
|
|
|
1.15
|
Less: Third-party operating fee reimbursements
|
|
|
(5,966)
|
|
|
(0.45)
|
|
|
(6,374)
|
|
|
(0.48)
|
|
Total general and administrative expenses
|
|
$
|
53,357
|
|
$
|
4.04
|
|
$
|
60,923
|
|
$
|
4.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $53.4 million ($4.04 per Boe) for the three months ended
June 30, 2016
,
a decrease of $7.5 million (12 percent) from $60.9 million ($4.54 per Boe) for
2015
. The
decrease in cash general and administrative expenses was primarily a result of
a general company-wide initiative to reduce general and administrative costs,
while the decrease in non-cash stock-based compensation was primarily due to an
increase in forfeiture estimates.
The
decrease in total general and administrative expenses per Boe was primarily due
to the reduction in general and administrative costs noted above while production
remained relatively flat period over period.
As the operator of certain oil and natural gas properties
in which we own an interest, we earn overhead reimbursements during the
drilling and production phases of the property.
We
earned reimbursements of $6.0 million and $6.4 million during the three months
ended
June 30, 2016
and 2015, respectively. This reimbursement is
reflected as a reduction of general and administrative expenses in the
consolidated statements of operations.
Loss on derivatives.
The following table sets forth the loss on derivatives for the
three months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
June 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Loss on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(279,805)
|
|
$
|
(146,549)
|
|
Natural gas derivatives
|
|
|
(16,889)
|
|
|
(850)
|
|
|
Total
|
|
$
|
(296,694)
|
|
$
|
(147,399)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from derivatives for the three months ended
June 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
June 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
160,968
|
|
$
|
103,129
|
|
Natural gas derivatives
|
|
|
7,781
|
|
|
9,123
|
|
|
Total
|
|
$
|
168,749
|
|
$
|
112,252
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in
value of our derivatives portfolio between periods and the related cash
settlements of those derivatives, which could be significant. To the extent the
future commodity price outlook declines between measurement periods, we will
have mark-to-market gains, while to the extent future commodity price outlook
increases between measurement periods, we will have mark-to-market losses.
Interest expense.
The following table sets forth interest
expense, weighted average interest rates and weighted average debt balances for
the three months ended June 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30,
|
(dollars in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Interest expense, as reported
|
|
$
|
54,502
|
|
$
|
53,482
|
Capitalized interest
|
|
|
-
|
|
|
1,179
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
54,502
|
|
$
|
54,661
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
-
|
|
|
3.0%
|
Weighted average interest rate - senior notes
|
|
|
5.9%
|
|
|
5.9%
|
|
Total weighted average interest rate
|
|
|
5.9%
|
|
|
5.8%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
-
|
|
$
|
156,340
|
Weighted average senior notes balance
|
|
|
3,350,000
|
|
|
3,350,000
|
|
Total weighted average debt balance
|
|
$
|
3,350,000
|
|
$
|
3,506,340
|
|
|
|
|
|
|
|
|
The decrease in the weighted average debt balance
for the three months ended June 30, 2016 as compared to 2015 was due to the
repayment of our credit facility using a portion of the proceeds from our October
2015 equity offering. The increase in interest expense was due
to a reduction in capitalized interest period over period, partially offset by
an overall decrease in the weighted average debt balance.
Income tax provisions.
We recorded an income tax benefit
of $158.2 million and $70.7 million for the three months ended
June 30, 2016
and 2015, respectively. The change in our income tax benefit was primarily due
to the increase in our net loss before income taxes. The effective income tax
rates for the three months ended
June 30, 2016
and 2015 were 37.3 percent and 37.0 percent,
respectively.
Six
Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$679.9 million for the six months ended
June 30, 2016
, a
decrease of
$271.1 million (28
percent
) from $950.9 million for
2015
. This
decrease was primarily due to the decrease in realized oil and natural gas
prices. Specific factors affecting oil and natural gas revenues include the
following:
·
total oil production was 16,237
MBbl
for the six months ended
June 30, 2016
, a
decrease
of 860
MBbl
(5
percent
) from 17,097
MBbl
for
2015
;
·
average realized oil price (excluding the effects of derivative
activities) was
$35.80
per Bbl during the six months ended
June 30, 2016
, a
decrease of 25
percent
from
$47.99
per Bbl
during
2015
. For
the six months ended June 30, 2016, our crude oil price differential relative
to NYMEX was $(3.85) per Bbl, or a realization of approximately 90.3 percent,
as compared to a crude oil price differential relative to NYMEX of $(5.34) per
Bbl, or a realization of approximately 90.0 percent, for 2015. We incur fixed
deductions from the posted Midland oil price based on the location of our oil
within the Permian Basin. Additionally, the basis differential between the
location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for
our oil directly impacts our realized oil price. For the six months ended June
30, 2016 and 2015, the average market basis differential between WTI-Midland
and WTI-Cushing was a price reduction of $0.01 per Bbl and $1.29 per Bbl,
respectively;
·
total natural gas production was 57,991
MMcf
for the six months ended
June 30, 2016
, an
increase
of 8,723
MMcf
(18
percent
) from 49,268
MMcf
for
2015
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$1.70
per Mcf during the
six months ended
June
30, 2016
, a decrease of 36
percent
from
$2.65
per Mcf during
2015
.
For the six months ended
June
30, 2016 and 2015
, we realized approximately 80.2 percent and 95.3 percent,
respectively, of the average NYMEX natural gas prices for the respective
periods.
Factors
contributing to the decrease in our realized gas price (excluding the effects
of derivatives) as a percent of NYMEX during the six months ended June 30, 2016
as compared to 2015 were (i) a decrease in the posted regional natural gas
prices on which we are paid while the NYMEX natural gas price decreased at a
lesser rate, (ii) increased deductions and fees from the regional natural gas
price, comparatively and (iii) the average Mont Belvieu price of $16.32 per Bbl
compared to $18.99 per Bbl during the six months ended June 30, 2016 and 2015
respectively.
During
December 2015, a third-party natural gas processing plant located in the
northern Delaware Basin became inoperable following an explosion. We estimate
that this event negatively impacted production for the six months ended June
30, 2016 by approximately
2.4
MBoepd.
The plant became fully
operational during April 2016.
Production expenses.
The following table provides the
components of our total oil and natural gas production costs for the six months
ended June 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
|
Amount
|
|
|
Boe
|
|
|
Amount
|
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
159,334
|
|
$
|
6.15
|
|
$
|
175,717
|
|
$
|
6.94
|
Workover costs
|
|
|
10,173
|
|
|
0.39
|
|
|
13,097
|
|
|
0.52
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
8,880
|
|
|
0.34
|
|
|
11,563
|
|
|
0.46
|
|
Production
|
|
|
46,794
|
|
|
1.81
|
|
|
67,423
|
|
|
2.66
|
|
|
Total oil and natural gas production expenses
|
|
$
|
225,181
|
|
$
|
8.69
|
|
$
|
267,800
|
|
$
|
10.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have
some control over lease operating expenses and workover costs on properties we
operate, but production and ad valorem taxes are related to commodity prices.
Lease operating expenses were $159.3 million
($6.15 per Boe) for the six months ended
June
30, 2016
, which was a decrease of
$16.4 million from $175.7 million ($6.94 per Boe) for the six months ended
June 30, 2015
.
The decrease in lease operating expenses during the six months ended
June 30, 2016
as compared to 2015 was due primarily to (i)
a
focused effort to identify operational cost efficiencies
and (ii) an overall decrease in the costs for
goods and services. The decrease in lease operating expenses per Boe was
primarily due to the reduction in lease operating expenses noted above while
there was a slight increase in production period over period.
Workover expenses were approximately
$10.2 million and $13.1 million for the six months ended June 30, 2016 and
2015, respectively. The decrease was primarily related to less overall activity
during 2016 as compared to 2015.
Production taxes per unit of production were
$1.81 per Boe during the six months ended
June
30, 2016
, a decrease of 32 percent
from $2.66 per Boe during
2015
. The decrease was directly related to the
decrease in oil and natural gas prices and due to tax credits of approximately
$3.7 million received during the first quarter of 2016 related to certain wells
in Texas qualifying for reduced severance tax rates as compared to
approximately $1.3 million of similar tax credits received during the second
quarter of 2015. Over the same period, our revenue per Boe prices (excluding
the effects of derivatives) decreased 30 percent.
Exploration
and abandonments expense.
The following table provides a breakdown of our exploration and abandonments
expense for the
six
months ended
June
30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
4,502
|
|
$
|
3,486
|
Exploratory dry hole costs
|
|
|
6,701
|
|
|
8,989
|
Leasehold abandonments
|
|
|
31,849
|
|
|
3,363
|
Other
|
|
|
1,082
|
|
|
1,937
|
|
Total exploration and abandonments
|
|
$
|
44,134
|
|
$
|
17,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense for the
periods presented above primarily consists of the costs of acquiring and
processing geophysical data and core analysis.
Our exploratory dry hole costs during the
six
months ended June 30, 2016 were primarily related to an uneconomic well in our
Delaware Basin area that was attempting to establish commercial production
through testing of multiple zones. Our exploratory dry hole costs during the
six
months ended June 30, 2015 were primarily related to (i) an uneconomic well in
our Delaware Basin area that was attempting to establish production in a zone not
previously producing in the general area and (ii) expensing an unsuccessful
well, which we did not operate, that was located in our New Mexico Shelf area.
For the
six
months ended
June 30, 2016 and 2015, we recorded approximately $31.8 million and $3.4 million,
respectively, of leasehold abandonments.
For the six months ended
June 30,
2016,
our abandonments were
primarily related to (i) drilling locations in our Delaware Basin and New
Mexico Shelf areas which, based on multiple factors, are no longer likely to be
drilled, (ii) acreage in our Delaware Basin and New Mexico Shelf areas where we
have no future development plans and (iii) expiring acreage.
Depreciation, depletion and amortization
expense.
The
following table provides components of our depreciation, depletion and
amortization expense for the six months ended
June
30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
|
Amount
|
|
|
Boe
|
|
|
Amount
|
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
580,044
|
|
$
|
22.39
|
|
$
|
562,092
|
|
$
|
22.21
|
Depreciation of other property and equipment
|
|
|
10,273
|
|
|
0.40
|
|
|
9,184
|
|
|
0.36
|
Amortization of intangible assets - operating rights
|
|
|
731
|
|
|
0.03
|
|
|
731
|
|
|
0.03
|
|
Total depletion, depreciation and amortization
|
|
$
|
591,048
|
|
$
|
22.82
|
|
$
|
572,007
|
|
$
|
22.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
was $580.0 million ($22.39 per Boe) for the six months ended
June 30, 2016
,
an increase of $17.9 million (3 percent) from $562.1 million ($22.21 per Boe)
for
2015
. The increase in depletion expense was primarily due to a modest
increase in production in addition to a slightly higher depletion rate per Boe
period over period. The increase in depletion expense per Boe period over
period was primarily due to a decrease in proved reserves caused by (i) lower
commodity prices period over period and (ii) reclassification of proved
reserves to unproven that are no longer expected to be developed within the
five years of their initial recording as required by SEC rules, both of which
were partially offset by capital cost reductions. Additionally, these factors
were largely offset by a non-cash impairment charge of approximately $1.5 billion
recorded in the first quarter of 2016.
The increase in depreciation expense was primarily
associated with additional other property and equipment related to buildings
and other items.
Impairments of long-lived assets.
We periodically review our long-lived assets to
be held and used, including proved oil and natural gas properties and their
integrated assets, whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable, for instance when there are
declines in commodity prices or well performance. We review our oil and natural
gas properties by depletion base. An impairment loss is indicated if the sum of
the expected undiscounted future net cash flows is less than the carrying
amount of the assets. If the estimated undiscounted future net cash flows are
less than the carrying amount of our assets, we recognize an impairment loss
for the amount by which the carrying amount of the asset exceeds the estimated
fair value of the asset.
We calculate the expected undiscounted future
net cash flows of our long-lived assets and their integrated assets using
management’s assumptions and expectations of (i) commodity prices, which are
based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii)
production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated
proved reserves and risk-adjusted probable and possible reserves, and (vii) prevailing
market rates of income and expenses from integrated assets.
At
June 30, 2016, o
ur estimates of commodity prices for purposes
of determining undiscounted future cash flows are based on the NYMEX strip,
which ranged from a 2016 price of $49.54 per barrel of oil and $3.04 per Mcf of
natural gas to a 2023 price of $57.77 per barrel of oil and $3.50 per Mcf of
natural gas. Commodity prices for this purpose were held flat after 2023.
We calculate the estimated fair values of our
long-lived assets and their integrated assets using a discounted future cash
flow model. Fair value assumptions associated with the calculation of
discounted future net cash flows include (i) market estimates of commodity
prices, (ii) pricing adjustments for differentials, (iii) production costs,
(iv) capital expenditures, (v) production volumes, (vi) estimated proved
reserves and risk-adjusted probable and possible reserves, (vii) prevailing
market rates of income and expenses from integrated assets and (viii) discount
rate. The expected future net cash flows were discounted using an annual rate
of 10 percent to determine fair value.
During the three months ended March 31, 2016,
NYMEX strip prices declined as compared to December 31, 2015, and as a result the
carrying amount of our Yeso field in our New Mexico Shelf area exceeded the expected
undiscounted future net cash flows resulting in a non-cash charge against
earnings of approximately $1.5 billion. The non-cash charge represented the
amount by which the carrying amount exceeded the estimated fair value of the
assets. We did not recognize an impairment charge during the three months ended
June 30, 2016.
It is reasonably possible that the estimate of
undiscounted future net cash flows of our long-lived assets may change in the
future resulting in the need to impair carrying values. The primary factors
that may affect estimates of future net cash flows are (i) commodity futures
prices, (ii) increases or decreases in production and capital costs, (iii)
future reserve volume adjustments, both positive and negative, to proved
reserves and appropriate risk-adjusted probable and possible reserves, (iv)
results of future drilling activities and (v) prevailing market rates of income
and expenses from integrated assets. If the oil and natural gas prices used in
this analysis would have been approximately 10 percent lower as of June 30,
2016 with no other changes in capital costs, operating costs, price
differentials, or reserve volumes, no impairment would be indicated.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the six months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
91,151
|
|
$
|
3.52
|
|
$
|
101,517
|
|
$
|
4.01
|
Non-cash stock-based compensation
|
|
|
28,473
|
|
|
1.10
|
|
|
30,945
|
|
|
1.22
|
Less: Third-party operating fee reimbursements
|
|
|
(12,472)
|
|
|
(0.48)
|
|
|
(12,738)
|
|
|
(0.50)
|
|
Total general and administrative expenses
|
|
$
|
107,152
|
|
$
|
4.14
|
|
$
|
119,724
|
|
$
|
4.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $107.2 million ($4.14 per Boe) for the six months ended
June 30, 2016
,
a decrease of $12.5 million (10 percent) from $119.7 million ($4.73 per Boe)
for
2015
. The decrease in cash general and administrative expenses was
primarily a result of a general company-wide initiative to reduce general and
administrative costs, while the decrease in non-cash stock-based compensation
was primarily due to an increase in forfeiture estimates.
The decrease in total general and
administrative expenses per Boe was primarily due to the reduction in general
and administrative costs noted above while there was a slight increase in
production period over period.
As the operator of certain oil and natural gas properties
in which we own an interest, we earn overhead reimbursements during the
drilling and production phases of the property.
We
earned reimbursements of $12.5 million and $12.7 million during the six months
ended
June 30, 2016
and 2015, respectively. This reimbursement is
reflected as a reduction of general and administrative expenses in the consolidated
statements of operations.
Gain (loss) on derivatives.
The following table sets forth the gain (loss) on derivatives for
the six months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
(208,665)
|
|
$
|
(36,269)
|
|
Natural gas derivatives
|
|
|
(8,187)
|
|
|
4,210
|
|
|
Total
|
|
$
|
(216,852)
|
|
$
|
(32,059)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from derivatives for the six months ended
June 30, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
412,095
|
|
$
|
263,315
|
|
Natural gas derivatives
|
|
|
14,584
|
|
|
16,093
|
|
|
Total
|
|
$
|
426,679
|
|
$
|
279,408
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in
value of our derivatives portfolio between periods and the related cash
settlements of those derivatives, which could be significant. To the extent the
future commodity price outlook declines between measurement periods, we will
have mark-to-market gains, while to the extent future commodity price outlook
increases between measurement periods, we will have mark-to-market losses.
Gain on disposition of assets, net.
In February 2016, we sold certain assets in the northern
Delaware Basin for proceeds of approximately $292.0 million, and recognized a
pre-tax gain of approximately $110.1 million.
Interest expense.
The following table sets forth interest expense, weighted average
interest rates and weighted average debt balances for the six months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
(dollars in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Interest expense, as reported
|
|
$
|
108,640
|
|
$
|
107,051
|
Capitalized interest
|
|
|
252
|
|
|
2,389
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
108,892
|
|
$
|
109,440
|
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
-
|
|
|
2.6%
|
Weighted average interest rate - senior notes
|
|
|
5.9%
|
|
|
5.9%
|
|
Total weighted average interest rate
|
|
|
5.9%
|
|
|
5.8%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
-
|
|
$
|
204,168
|
Weighted average senior notes balance
|
|
|
3,350,000
|
|
|
3,350,000
|
|
Total weighted average debt balance
|
|
$
|
3,350,000
|
|
$
|
3,554,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The decrease in the weighted average debt
balance for the six months ended June 30, 2016
as compared to 2015 was due to the repayment of our credit
facility using a portion of the proceeds from our October 2015 equity
offering. The
increase in interest
expense was due to a reduction in capitalized interest period over period,
partially offset by an overall decrease in the weighted average debt balance.
Income tax provisions.
We recorded an income tax benefit of
$752.0 million and $66.6 million for the six months ended
June 30, 2016
and 2015, respectively. The change in our income tax benefit was primarily due
to the increase in our net loss before income taxes. The effective income tax
rates for the six months ended
June 30, 2016
and 2015 were 36.9 percent and 37.1 percent,
respectively.
Capital Commitments, Capital Resources and Liquidity
Capital commitments.
Our primary needs for cash are development, exploration and acquisition
of oil and natural gas assets, midstream joint ventures and other capital
commitments, payment of contractual obligations and working capital
obligations. Funding for these cash needs may be provided by any combination of
internally-generated cash flow, financing under our credit facility or proceeds
from the disposition of assets or alternative financing sources, as discussed
in
“—
Capital resources” below.
Oil and natural gas properties.
Our costs incurred on oil and natural gas
properties, excluding acquisitions and asset retirement obligations, during the
six
months ended
June 30, 2016
and 2015 totaled $525.6 million and $1.3 billion, respectively. The decrease
was primarily due to our reduced drilling and completion activity level during
the first half of 2016 as compared to the first half of 2015. The decrease is
primarily related to our intent to adjust our capital spending to be within our
cash flow, excluding unbudgeted acquisitions. The primary reason for the
differences in the costs incurred and cash flow expenditures was our issuance
of approximately 2.2 million shares of common stock related to our March 2016
acquisition and timing of payments. The 2016 expenditures were primarily funded
in part from (i) cash flows from operations, (ii) proceeds from our February
2016 divestiture and (iii) our issuance of approximately 2.2 million shares of
common stock related to our March 2016 acquisition.
2016 capital budget
.
In November 2015, we announced our 2016 base
capital budget, excluding acquisitions, of approximately $1.4 billion, with
drilling and completion capital accounting for approximately $1.2 billion.
During the remainder of 2016, our intent is to
manage our capital spending, as we did during the first half of 2016, to be
within our cash flows. Based on current commodity prices and costs, our capital
plan is in the range of $1.1 billion to $1.3 billion. However, if we were
to outspend our cash flows, we could use our (i) cash on hand, (ii) credit
facility and (iii) other financing sources to fund any cash flow deficits. The
actual amount and timing of our expenditures may differ materially from our
estimates as a result of, among other things, actual drilling results, the
timing of expenditures by third parties on projects that we do not operate, the
costs of drilling rigs and other services and equipment, regulatory,
technological and competitive developments and market conditions. In addition,
under certain circumstances, we may consider increasing, decreasing or
reallocating our capital spending plans. Our 2016 capital program is expected
to continue focusing on horizontal drilling across all our core areas.
Acquisitions.
The
following table reflects o
ur expenditures for
acquisitions of proved and unproved properties for the six months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
256,109
|
|
$
|
2,243
|
|
Unproved
|
|
|
157,407
|
|
|
34,050
|
|
|
Total property acquisition costs (a)
|
|
$
|
413,516
|
|
$
|
36,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the property
acquisition costs above are budgeted unproved leasehold acreage acquisitions
of $23.3 million and $29.8 million for the six months ended June 30, 2016 and
2015, respectively. For the six months ended June 30, 2016, our unbudgeted
acquisitions are primarily comprised of approximately $374.3 million of
property acquisition costs related to our March 2016 unbudgeted acquisition.
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual obligations.
Our contractual obligations include long-term
debt, cash interest expense on debt, operating lease obligations, purchase
obligations, employment agreements with officers, derivative liabilities,
investment contributions related to Alpha Crude Connecter, LLC, our other
midstream entity in the southern Delaware Basin and other obligations. Since
December 31, 2015, the changes in our contractual obligations are not material.
See Note 9 of the Condensed Notes to Consolidated Financial Statements included
in “Item 1. Consolidated Financial Statements (Unaudited)” for additional
information regarding our long-term debt and “Item 3.
Quantitative and Qualitative Disclosures About Market Risk” for information
regarding the interest on our long-term debt and information on changes in the
fair value of our open derivative obligations during the six months ended
June 30, 2016
.
Off-balance sheet arrangements.
Currently, we do not have any material
off-balance sheet arrangements.
Capital resources.
Our primary sources of liquidity have been
cash flows generated from (i) operating activities and
cash settlements received from derivatives
, (ii) borrowings under our credit facility, (iii) proceeds
from bond and equity offerings and (iv) proceeds from the sale of assets.
During the remainder of 2016, our intent is to manage our capital spending, as
we did during the first half of 2016, to be within our cash flows. Based on
current commodity prices and costs, our capital plan is in the range of $1.1
billion to $1.3 billion. However, if we were to outspend our cash flows,
we could use our (i) cash on hand, (ii) credit facility and (iii) other
financing sources to fund any cash flow deficits.
The following table summarizes our changes in
cash and cash equivalents for the six months ended
June 30, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
249,825
|
|
$
|
488,934
|
Net cash provided by (used in) investing activities
|
|
|
14,836
|
|
|
(1,284,189)
|
Net cash provided by (used in) financing activities
|
|
|
(11,981)
|
|
|
795,514
|
|
Net increase in cash and cash equivalents
|
|
$
|
252,680
|
|
$
|
259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from
operating activities.
The decrease in operating cash flows during the
six
months ended June 30, 2016 as compared to
the same period in 2015 was primarily due to (i) a decrease in oil and natural
gas revenues of approximately $271.1 million and (ii) approximately $64.8
million of negative variances in operating assets and liabilities, partially
offset by (i) approximately $42.6 million decrease in cash production expense,
(ii) an increase in operating cash flow of approximately $40.7 million due to a
cash tax benefit of approximately $12.0 million for the
six
months ended
June 30, 2016 compared to cash tax expense of approximately $28.7 million
during 2015
and
(iii) a cash decrease in general and administrative expense of approximately
$10.1 million.
Our net cash provided by operating
activities included a reduction of approximately $25.9
million and a benefit of approximately $38.9
million
for the
six
months ended June 30, 2016 and 2015,
respectively, associated with changes in working capital items. Changes in
working capital items adjust for the timing of receipts and payments of actual
cash.
Cash
flow used in investing activities.
During the six months ended
June 30, 2016
and
2015, we invested approximately $0.7 billion and $1.5 billion, respectively,
for capital expenditures on oil and natural gas properties. Additionally, we
received approximately $294.3 million related to proceeds from the disposition
of assets and approximately $426.7 million from settlements on derivatives
during the six months ended June 30, 2016 as compared to $279.4 million from
settlements on derivatives during the comparable period in 2015.
Cash flow from
financing activities.
Net cash used by financing activities
was approximately $12.0 million for the
six
months ended
June 30, 2016, while during 2015 we had net cash provided by financing
activities of approximately $795.5 million. Below is a description of our
significant financing activities:
·
In March 2015, we issued shares of our common stock in a public
offering and received net proceeds of approximately $741.5 million. We
used a portion of the net proceeds from this offering to repay all outstanding
borrowings under our credit facility and the remainder for general corporate
purposes.
·
During the first six months of 2015, we had net borrowings on our
credit facility of $66.5 million.
·
During the first six months of 2016, we had no outstanding
borrowings under our credit facility.
At
June 30, 2016,
we
had unused commitments of approximately
$2.5
billion
based on bank commitments of $2.5 billion. The maturity date of the credit
facility is May 9, 2019.
Advances
on our amended and restated credit facility bear interest, at our option, based
on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) or (ii) a
Eurodollar rate (substantially equal to the London Interbank Offered Rate). The
credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate
advances varied, with interest margins ranging from 125 to 225 basis points and
25 to 125 basis points, respectively, per annum depending on the utilization of
the borrowing base. We pay commitment fees on the unused portion of the
available commitment ranging from 30.0 to 37.5 basis points per annum,
depending on utilization of the borrowing base. Subject to certain
restrictions, with respect to our public debt ratings, the collateral securing
the facility may be released.
In conducting
our business, we may utilize various financing sources, including the issuance of
(i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred
stock, (iv) common stock and (v) other securities.
Over
the last three years, we have demonstrated our use of the capital markets by
issuing common stock and senior unsecured debt. There are no assurances that we
can access the capital markets to obtain additional funding, if needed, and at
cost and terms that are favorable to us.
We may also sell assets and
issue securities in exchange for oil and natural gas assets or interests in energy
companies. Additional securities may be of a class senior to common stock with
respect to such matters as dividends and liquidation rights and may also have
other rights and preferences as determined from time to time. Utilization of some
of these financing sources may require approval from the lenders under our
credit facility.
Liquidity.
Our principal
sources of liquidity are cash on hand and available borrowing capacity under
our credit facility. At June
30, 2016,
we had approximately $481.2
million
of
cash on hand.
At June 30, 2016, our
commitments from our bank group were $2.5 billion. We expect we will maintain
our $2.5 billion in commitments until our next scheduled redetermination in May
2017. At June 30, 2016, our borrowing base was $2.8 billion.
There is no assurance that our borrowing base will not be
reduced, which could affect our liquidity. Upon
a subsequent redetermination, our borrowing base could be substantially
reduced.
We may from time to time
seek to retire or purchase our outstanding debt through cash purchases and/or
exchanges for other debt or equity securities, in open market purchases,
privately negotiated transactions or otherwise. Such repurchases or exchanges,
if any, will depend on prevailing market conditions, our liquidity
requirements, contractual restrictions and other factors. The amounts involved
may be material.
Debt ratings
.
We receive debt
credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and
Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular
reviews. S&P’s corporate rating for us is “BB+” with a stable outlook.
Moody’s corporate rating for us is “Ba1” with a stable outlook. S&P and
Moody’s consider many factors in determining our ratings including: the
industry in which we operate, production growth opportunities, liquidity, debt
levels and asset and reserve mix. A reduction in our debt ratings could
negatively affect our ability to obtain additional financing or the interest
rate, fees and other terms associated with such additional financing.
A downgrade in our credit ratings could
negatively impact our costs of capital and our ability to effectively execute
aspects of our strategy. Further, a downgrade in our credit ratings could
affect our ability to raise debt in the public debt markets, and the cost of
any new debt could be much higher than our outstanding debt. These and other
impacts of a downgrade in our credit ratings could have a material adverse
effect on our business, financial condition and results of operations.
As of the filing of this Quarterly
Report, no changes in our credit ratings have occurred since June 30, 2016;
however, we cannot be assured that our credit ratings will not be downgraded in
the future.
Book
capitalization and current ratio
.
Our net book
capitalization at June
30, 2016
was $8.7
billion, consisting of $0.5 billion
of cash and cash equivalents, debt of $
3.3 b
illion
and stockholders’ equity of $
5.9
billion. Our net
debt to book capitalization was 33
percent and
31
percent
at June 30, 2016 and December
31, 2015, respectively. Our ratio of current assets to current liabilities was
1.93
to 1.0 at June 30, 2016 as compared to
2.20 to 1.0 at December 31, 2015.
Inflation and
changes in prices.
Our revenues, the value of our assets, and our
ability to obtain bank financing or additional capital on attractive terms have
been and will continue to be affected by changes in commodity prices and the
costs to produce our reserves. Commodity prices are subject to significant
fluctuations that are beyond our ability to control or predict. During the six
months ended June
30, 2016,
we received an average of $35.80
per Bbl of
oil and $1.70
per Mcf of natural gas before
consideration of commodity derivative contracts compared to $47.99
per Bbl of oil and $2.65
per
Mcf of natural gas in the six months ended June 30, 2015. Although
certain of our costs are affected by general inflation, inflation does not
normally have a significant effect on our business.
Critical
Accounting Policies, Practices and Estimates
Our historical consolidated financial statements and related
condensed notes to consolidated financial statements contain information that
is pertinent to our management’s discussion and analysis of financial condition
and results of operations. Preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
that our management make estimates, judgments and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses, and the
disclosure of contingent assets and liabilities. However, the accounting
principles used by us generally do not change our reported cash flows or
liquidity. Interpretation of the existing rules must be done and judgments made
on how the specifics of a given rule apply to us.
In management’s opinion, the more significant reporting
areas impacted by management’s judgments and estimates are the choice of
accounting method for oil and natural gas activities, oil and natural gas
reserve estimation, asset retirement obligations, impairment of long-lived
assets, valuation of stock-based compensation, valuation of business
combinations, valuation of financial derivative instruments and income taxes.
Management’s judgments and estimates in these areas are based on information
available from both internal and external sources, including engineers,
geologists and historical experience in similar matters. Actual results could
differ from the estimates as additional information becomes known.
There have been no material changes in our critical
accounting policies and procedures during the
six
months ended June 30, 2016.
See our disclosure of critical accounting policies in “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations” and
“Item 8. Financial Statements and Supplementary Data” of our Annual Report on
Form 10-K for the year ended December 31, 2015, filed with the United States
Securities and Exchange Commission (the “SEC”) on February 25, 2016.
Recent
accounting pronouncements.
In May
2014, the Financial Accounting Standards Board (“the FASB”) issued Accounting
Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with
Customers (Topic 606),” which outlines a new, single comprehensive model for
entities to use in accounting for revenue arising from contracts with customers
and supersedes most current revenue recognition guidance, including
industry-specific guidance. This new revenue recognition model provides a
five-step analysis in determining when and how revenue is recognized. The new
model will require revenue recognition to depict the transfer of promised goods
or services to customers in an amount that reflects the consideration a company
expects to receive in exchange for those goods or services.
In August 2015, the FASB issued ASU
No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of
the Effective Date,” which deferred the effective date of ASU 2014-09 by one
year. That new standard is now effective for annual reporting periods beginning
after December 15, 2017. An entity can apply ASU 2014-09 using either a full
retrospective method, meaning the standard is applied to all of the periods
presented, or a modified retrospective method, meaning the cumulative effect of
initially applying the standard is recognized in the most current period
presented in the financial statements. We are evaluating the impact that this
new guidance will have on our consolidated financial statements.
In February 2016, the FASB issued
ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease
guidance. The new lease standard requires all leases with a term greater than
one year to be recognized on the balance sheet while maintaining substantially
similar classifications for finance and operating leases. Lease expense
recognition on the income statement will be effectively unchanged. This
guidance is effective for reporting periods beginning after December 15, 2018
and early adoption is permitted. We are evaluating the impact that this new
guidance will have on our consolidated financial statements.
In March 2016, the FASB issued ASU
No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements
to Employee Share-based Payment Accounting,” which changes the accounting and
presentation for share-based payment arrangements in the following areas: (i)
recognition in the statement of operations of excess tax benefits and
deficiencies; (ii) cash flow presentation of excess tax benefits and
deficiencies; (iii) minimum statutory withholding thresholds and the
classification on the cash flow statement of the withheld amounts; and (iv) an
accounting policy election to recognize forfeitures as they occur. This
guidance is effective for reporting periods beginning after December 15, 2016
and early adoption is permitted. We are evaluating the impact that this new
guidance will have on our consolidated financial statements.